The present invention relates to a method for controlling the pH of steam fluids. More particularly, the invention relates to a method for (1) preserving the reservoir rock or gravel packing in oil wells being subjected to steam enhanced oil recovery techniques; (2) controlling corrosion produced by an acidic vapor phase condensate of the steam; and (3) improving the steam injection rate into the formation.
Steam injection techniques, such as steam stimulation and steamflooding, have been used to recover immobile heavy oils and to enhance the oil recovery from older wells where the natural field pressures are too low for unassisted production. They are designed to reduce the reservoir flow resistance by reducing the viscosity of the crude.
These techniques involve injection into the well of a high temperature wet steam in cycles of thousands of cubic meters at a time. Wet steam is a mixture of steam and varying amount of hot liquid water, the quality of wet steam generally ranging from 35% to 80%. Because of the density difference between the two phases of the wet steam, the vapor phase preferentially enters the upper part of the injection interval and the liquid phase preferentially enters the lower part.
When groundwater, river water, or lake water is used as feedwater to generate wet steam, the liquid water phase is generally basic (having a pH in excess of 11) and the vapor phase of the wet steam, when condensed, is acidic (having a pH of about 4.0 to 4.5). This partitioning is because of bicarbonate contained in the source water decomposing to CO.sub.2 and OH.sup.-, as shown in Equation 1 below: ##STR1## The CO.sub.2 is volatile and enters the vapor phase, which produces a low pH in the liquids condensed from the vapor phase The OH.sup.- ion enters the liquid phase and causes a high pH in the liquid phase.
Associated with using these wet steams in steam injection is the problem of silica and silicate dissolution. Coupled with high fluid temperatures, both the liquid phase and the liquids from the condensed vapor phase are capable of rapidly dissolving reservoir rocks, such as sandstone, carbonate, diatomite, porcellanite and the like. For pH values above 11.0 and temperatures above 177.degree. C., the silica and silicate dissolution rates are orders of magnitude higher than at neutral/ambient conditions. Also, because the reactions for dissolving siliceous reservoir rocks are base consumers in alkaline fluids, the pH of the residual fluid decreases rapidly as the fluid moves away from the wellbore, causing the dissolution reactions and solubility to diminish rapidly and causing the reaction products downstream (such as aluminosilicates and other metal silicates) to precipitate in the pores. This precipitation decreases the formation permeability and decreases well injectivity.
Dissolution of the gravel pack has been shown to be primarily a function of the pH and temperature of the injected liquid-phase water. Prior attempts at solution of the problem have focused on these aspects. For example, by keeping the pH of the injected hot water below 10, gravel pack dissolution can be decreased sharply. This may be accomplished by (1) selection of feed waters having low total carbonate concentrations (less than 10 mg total carbonate/L), (2) treating the feed water with HCl to yield the desired effluent pH, (3) using a total deionizer to remove both cations and anions from the feed water, or (4) protectively coating the gravel and/or reservoir rocks.
With regard to the first proposed solution, selection of feed waters is often impractical as the large quantities of water used are not available from a choice of sources. The second proposed solution, using HCl to neutralize the bicarbonate alkalinity, was suggested by M. G. Reed in "Gravel Pack and Formation Sandstone Dissolution During Steam Injection", Journal of Petroleum Technology, Vol. 32, pp. 941-949 (1980). But this approach suffers from considerations of cost as well as feasibility of the method. That is, addition of too much acid will cause severe corrosion of the steam generator and too little will result in insufficient depression of the pH to alleviate silica loss. With regard to the third proposed solution, the cost of a total deionizer is prohibitive, both in terms of capital costs as well as daily maintenance costs. With regard to the fourth proposed solution, complete coating of the gravel with a material, such as soybean lecithin described in U.S. Pat. No. 4,323,124, is not assured and driving the material out into the reservoir toward the production well is impractical. Furthermore, this patent does not address the problems of formation dissolution out in the formation away from the well bore.
U.S. Pat. No. 3,438,443 discloses another approach for a solution to the problem through the use of alkali metal silicates to saturate the water phase with silica and thus, hopefully, preventing the dissolution of siliceous formation material. However, alkali metal silicates are costly and the process also requires careful pH control. Moreover, they cause severe formation damage from precipitation of the added silicates.
Still other oil recovery processes as described in U.S. Pat. Nos. 3,500,931; 4,222,439; and 4,223,731 utilize chemicals, such as ammonium hydroxide, ammonium bisulfite, ammonium sulfite in separate injection steps to enhance oil recovery. However, these processes utilize the chemicals in a separate step, generally not including steam, and do not recognize the problems associated with the pH partitioning between the vapor phase of the steam and the residual water phase of the steam during the steps that include steam injection. Still another oil recovery process described in U.S. Pat. No. 4,441,555 utilizes a carbonated water flooding step before a steam drive to enhance the recovery of viscous oil. This process also does not recognize the problems of pH partitioning during steps that require a steam drive.
U.S. Pat. No. 4,475,595 to Watkins et al, filed Aug. 23, 1982, which is hereby incorporated by reference, addresses the problem of silica dissolution during steam injection. Watkins et al discuss adding an ammonium salt to the generator feedwater or to the steam itself. Ammonia gas partitions to the vapor phase leaving an acidic component to neutralize the OH.sup.- ions in the residual liquid phase.
Another problem associated with Equation (1) is its effect on the vapor phase of the steam. The carbon dioxide partitions into the vapor phase while the hydroxyl ions remain in the liquid phase. The vapor phase of the wet steam, when condensed, may have an acidic pH of about 4.0 to 4.5 resulting from the carbon dioxide combining with water to form carbonic acid, a known corrosive. Carbonic acid causes corrosion of steel conduit which it contacts and combines with alkaline earth scale which adheres to the surfaces of the pores in the reservoir, the well bore and other conduits and builds up in thickness over a period of time.
U.S. Pat. No. 4,476,930 to Watanabe, filed Aug. 23, 1982, which is hereby incorporated by reference, addresses the problem of scale inhibition during steam generation. Watanabe discusses adding an ammonium salt to the steam generator feedwater. Ammonia gas partitions to the vapor phase and inhibits the production of carbonic acid.
While some well-treating methods have met with some success, in particular applications, the need exists for a further improved steam injection treatment which simultaneously inhibits silica dissolution of gravel pack and silicate formations while controlling corrosion produced by an acidic vapor phase condensate. Accordingly, it is the principle object of this invention to provide such a method.
A further object of the present invention is to provide a method for improving overall steam injectivity into a hydrocarbon-containing formation.
A further object of the present invention is to provide a method for improving steam dump/heap leaching operations in mining and steam in situ mineral mining.